Oil-based drilling fluids for high pressure and high temperature drilling operations

ABSTRACT

Oil-based drilling fluid compositions comprising an oil phase comprising a base oil, an aqueous phase comprising water, at least one emulsifier, and one or more additives. The at least one emulsifier comprises an amino amide comprising the formula R—CO—NH—R′—NH—R″—NH 2 , where R is a fatty acid alkyl and R′ and R″ are alkyl groups. The one or more additives are chosen from a wetting agent, a rheology modifier, a fluid-loss control additive, and a weighting additive. Methods of making the oil-based drilling fluid compositions and methods of drilling a subterranean well utilizing the oil-based drilling fluid compositions are also provided.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority to U.S. Non-Provisional applicationSer. No. 16/055,867 filed Aug. 6, 2018, which claims the benefit of U.S.Provisional Application Ser. No. 62/545,516 filed Aug. 15, 2017, both ofwhich are incorporated herein by reference.

TECHNICAL FIELD

Embodiments of the present disclosure generally relate to oil-baseddrilling fluids for use in high pressure and high temperature drillingoperations. More specifically, embodiments of the present disclosurerelate to oil-based drilling fluids comprising an emulsifier.

BACKGROUND

Drilling operations to drill a new wellbore for hydrocarbon extraction,for example, include the common practice of continuously circulating adrilling fluid (alternatively known as a drilling mud) through thewellbore during the drilling operation. The drilling fluid is pumpedinto the drill pipe to the bottom of the borehole where the drillingfluid then flows upwardly through the annular space between the wellborewall and the drill pipe, and finally flows from the wellbore where it isrecovered for secondary processing. Specifically, the drilling fluid ismechanically or chemically treated to remove captured solids and drillcuttings from the drilling fluid and before recirculation back throughthe wellbore.

Given the circulating nature of drilling fluid and its functionality incapturing solids and cuttings during drilling operations, drillingfluids must be free-flowing with a relatively low viscosity in order tofacilitate pumping while having sufficient substance to retain andtransport the cuttings and other solids and to suspend the weightingmaterial so as to maintain a drilling fluid column of uniform density inthe wellbore during static and circulating conditions. The drillingfluid must also have a gel strength sufficient to suspend the solids andcuttings if circulation of the drilling fluid is stopped to preventaccumulation of solids at the bottom of the wellbore. Solidsaccumulating at the bottom of the wellbore would potentially result injamming of the drill as well as physical blockage of the drillingfluid's flow path.

Drilling in deep wells is complicated by geological conditions thatinvolve high pressures and high temperatures (HPHT). As wellbores areincreased in depth, the pressure and temperature at the base of thewellbore is elevated. The industry-defined definition of HPHT conditionstypically include a wellbore temperature greater than 300° F. (149° C.)and a wellbore pressure greater than 10,000 psi (68.9 MPa). Elevatedtemperatures have a detrimental effect upon drilling fluids withbreakdown of components unable to sustain the elevated temperatures. Atelevated temperatures some drilling fluids may begin to solidify orexperience viscosity increases that may impede circulation.

SUMMARY

Known drilling fluids typically contain emulsifiers, among otherconstituent components, that are not suitable for HPHT drilling becausethey decompose under HPHT conditions. Thus, there are ongoing needs fordrilling fluids and included emulsifiers for drilling fluids that arethermally stable under HPHT conditions and while providing suitablerheological properties.

Embodiments of the present disclosure are directed to emulsifiers foroil-based drilling fluids, associated drilling fluid compositionscomprising the emulsifier, and methods for making the oil-based drillingfluid.

According to one or more embodiments, an oil-based drilling fluidincludes an oil phase which includes a base oil, an aqueous phase whichincludes water, at least one emulsifier, and one or more additiveschosen from a wetting agent, a rheology modifier, a fluid-loss controladditive, and a weighting additive. The at least one emulsifiercomprises an amino amide comprising the formula R—CO—NH—R′—NH—R″—NH₂,where R is a fatty acid alkyl and R′ and R″ are alkyl groups.

According to another aspect, a method for making an oil-based drillingfluid includes mixing a base oil, at least one emulsifier, andoptionally at least one wetting agent to form a first mixture. Theemulsifier includes an amino amide having the formulaR—CO—NH—R′—NH—R″—NH₂, where R is a fatty acid alkyl and R′ and R″ arealkyl groups. Additionally, the method includes optionally, mixing atleast one rheology modifier, and alkalinity adjuster into the firstmixture to form a second mixture, optionally, mixing at least onefluid-loss control additive into the second mixture to form a thirdmixture, mixing a brine solution into the first mixture or the thirdmixture to form a fourth mixture, and mixing a weighting additive intothe fourth mixture to form the oil-based drilling fluid composition.

According to a further aspect, a method for drilling in a subterraneanwell includes providing an oil-based drilling fluid compositionaccording to any one of the other aspects and operating a drill in awellbore in the presence of the oil-based drilling fluid composition.

Additional features and advantages of the described embodiments will beset forth in the detailed description which follows, and in part will bereadily apparent to those skilled in the art from that description orrecognized by practicing the described embodiments, including thedetailed description which follows and the claims.

BRIEF DESCRIPTION OF FIGURES

The following detailed description of the illustrative embodiments canbe understood when read in conjunction with the following drawings.

FIG. 1 provides a graph of the viscosities of various tested drillingfluids as a function of shear rate at both 0° C. and 50° C.

FIG. 2 provides a graph of the storage modulus (G′) and the loss modulus(G″) of various tested drilling fluids as a function of percent strainat 50° C.

FIG. 3 provides a graph of the phase angle of various tested drillingfluids as a function of percent strain at 50° C.

DETAILED DESCRIPTION

Embodiments of the present disclosure are directed to emulsifiers foroil-based drilling fluids and additionally oil-based drilling fluidcompositions incorporating the disclosed emulsifiers. The oil-baseddrilling fluid is a combination of an oil phase, an aqueous phase, andat least one emulsifier. The emulsifier may comprise an amino amidecomprising the formula R—CO—NH—R′—NH—R″—NH₂, where R is a fatty acidalkyl and R′ and R″ are alkyl groups. For convenience, the emulsifiercomprising an amino amide having the formula R—CO—NH—R′—NH—R″—NH₂, whereR is a fatty acid alkyl and R′ and R″ are alkyl groups, is alternativelyalso referred to as the Formula 1 emulsifier throughout this disclosure.

To drill a subterranean well, a drill string, including a drill bit anddrill collars to weight the drill bit, is inserted into a predrilledhole and rotated to cause the drill bit to cut into the rock at the endof the hole. The drilling operation produces rock fragments. To removethe rock fragments from the end of the wellbore, a drilling fluid, suchas the oil-based drilling fluid composition, is pumped downhole throughthe drill string to the drill bit. The drilling fluid cools the drillbit, provides lubrication, and lifts the rock fragments known ascuttings away from the drill bit. The drilling fluid carries thecuttings uphole as the drilling fluid is recirculated back to thesurface. At the surface, the cuttings are removed from the drillingfluid through a secondary operation, and the drilling fluid isrecirculated back downhole through the drill string to the end of thewellbore for collection of further cuttings. It will be appreciated byone skilled in the art that multiple terms familiar to those skilled inthe art may be used to describe the same thing. For example, asubterranean well may alternatively be called a wellbore or borehole andusage of one term is meant to encompass each of the related terms aswell.

Drilling fluids include drilling muds, packer fluids, suspension fluidsand completion fluids. Generically, drilling fluids serve a number offunctions with different types specializing in a particular function orfunctions. In one or more embodiments, the oil-based drilling fluidcomposition suspends the cuttings and weighting material and transportsthe cutting to the wellbore surface with the oil-based drilling fluidcomposition. Additionally, the oil-based drilling fluid composition mayabsorb gases in the wellbore, such as carbon dioxide (CO₂), hydrogensulfide (H₂S), and methane (CH₄), and transport them to the wellboresurface for release, sequestration, or burn-off. The oil-based drillingfluid composition additionally provides buoyancy to the drill stringrelieving the tension on the drill string as the length of the wellboreincreases. In one or more embodiments, the oil-based drilling fluidcomposition also provides a cooling and lubrication functionality forcooling and lubrication of the bit and drill string utilized in boringoperations. In other embodiments, the oil-based drilling fluidcomposition also controls subsurface pressures. Specifically, theoil-based drilling fluid composition provides hydrostatic pressure inthe wellbore to provide support to the sidewalls of the wellbore andprevent the sidewalls from collapsing and caving in on the drill string.Additionally, the oil-based drilling fluid composition provideshydrostatic pressure in the bore to prevent fluids in the downholeformations from flowing into the wellbore during drilling operations.

Under certain extreme downhole conditions, such as excessive temperatureor difficult formations, some of the properties of the drilling fluidmay be altered. For example, interaction of a drilling fluid with aformation having swelling clay, dispersible clay, or both, or subjectingthe drilling fluid to extreme downhole temperatures may cause thedrilling fluid to thicken or thin resulting in an excessive increase ordecrease in viscosity, or any combination of these. For example, adrilling fluid utilized in high pressure and high temperature (HPHT)operations may experience a wellbore temperature greater than 300° F.(149° C.) and a wellbore pressure greater than 10,000 psi (68.9 MPa)which is the industry-defined definition of HPHT conditions. Under HPHTconditions, drilling fluids may decompose or experience undesirablechanges in rheology. Additionally, gas influx into the wellbore may thinor chemically destabilize the drilling fluid. Evaporite formations mayalso destabilize the drilling fluid.

Embodiments of the oil-based drilling fluid composition are formulatedto provide improved rheology. Specifically, the oil-based drilling fluidcomposition is formulated to comprise a greater viscosity at low shearrates than commercially available HPHT oil-based drilling fluids and alesser viscosity at high shear rates than commercially available HPHToil-based drilling fluids. As used in this disclosure, a low shear rateis defined as less than 10 inverse seconds (s⁻¹) and a high shear rateis defined as greater than 100 s⁻¹. The greater viscosity at low shearrates enables the oil-based drilling fluid composition to effectivelyhold cuttings when drilling operations are halted and retain theweighting material in suspension. Conversely, the lesser viscosity athigh shear rates necessitates less power for circulation of theoil-based drilling fluid composition during drilling operations.

The oil-based drilling fluid includes at least one emulsifier. Theemulsifier assists in the formation of an emulsion of the aqueous phaseof the oil-based drilling fluid composition within the oil phase of theoil-based drilling fluid composition. The inclusion of the emulsifier inthe oil-based drilling fluid compositions helps prevent separation ofthe oil phase and the aqueous phase and ensures that entrained solidsremain dispersed in the oil phase. Emulsifiers also affect theperformance of additives designed to viscosify the drilling fluid, suchas organophilic clays.

In one or more embodiments, the emulsifier comprises an amino amidecomprising the formula R—CO—NH—R′—NH—R″—NH₂ (Formula 1 emulsifier) andhas a chemical structure as reflected infra.

In one or more embodiments, the amount of the Formula 1 emulsifier inthe drilling fluid composition may be from 0.05 weight percentage (wt.%) to 5 wt. %, from 0.1 wt. % to 2 wt. %, from 0.1 wt. % to 1.5 wt. %,from 0.1 wt. % to 1 wt. %, from 0.5 wt. % to 2.5 wt. %, from 0.5 wt. %to 2 wt. %, from 0.5 wt. % to 1.5 wt. %, from 0.5 wt. % to 1 wt. %, from0.75 wt. % to 2.5 wt. %, from 0.75 wt. % to 2 wt. %, from 0.75 wt. % to1.5 wt. %, from 0.75 wt. % to 1 wt. %, from 0.8 wt. % to 1.1 wt. %, from0.8 wt. % to 1 wt. %, or from 0.9 wt. % to 1.1 wt. %, based on the totalweight of the drilling fluid composition. The oil-based drilling fluidmay include additional emulsifiers. Additional example emulsifiersinclude an invert emulsifier and oil-wetting agent for synthetic baseddrilling fluid systems such as LE SUPERMUL™ commercially available fromHalliburton Energy Services, Inc. and MUL XT commercially available fromM-I SWACO. LE SUPERMUL™ is a carboxylic acid terminated polyamide.

In one or more embodiments, the total amount of the emulsifier in thedrilling fluid composition including both the Formula 1 emulsifier andadditional emulsifiers may be from 0.05 wt. % to 5 wt. %, from 0.1 wt. %to 2.5 wt. %, from 0.1 wt. % to 1.5 wt. %, from 0.1 wt. % to 1 wt. %,from 0.5 wt. % to 2.5 wt. %, from 0.5 wt. % to 2 wt. %, from 0.5 wt. %to 1.5 wt. %, from 0.5 wt. % to 1 wt. %, from 0.75 wt. % to 2.5 wt. %,from 0.75 wt. % to 2 wt. %, from 0.75 wt. % to 1.5 wt. %, from 0.75 wt.% to 1 wt. %, from 0.8 wt. % to 1.1 wt. %, from 0.8 wt. % to 1 wt. %, orfrom 0.9 wt. % to 1.1 wt. %, based on the total weight of the drillingfluid composition.

In one or more embodiments, the R group in the amino amide comprisingthe formula R—CO—NH—R′—NH—R″—NH₂ comprises a fatty acid alkyl. Invarious embodiments, the R group may be C₁₅H₃₁, C₁₇H₃₅, C₂₁H₄₃ orC₈H₁₇CHCHC₇H₁₄.

In one or more embodiments, the R′ group in the amino amide comprisingthe formula R—CO—NH—R′—NH—R″—NH₂ comprises an alkyl group. The term“alkyl,” means a saturated straight or branched chain, substituted orunsubstituted hydrocarbon radical having from 1 to 500 carbon atoms. Theterm “(C₁-C₂₀)alkyl” means a alkyl having 1 to 20 carbon atoms that isunsubstituted or substituted by one ore more R^(s). In one or moreembodiments, the R′ group is an unsubstituted alkyl. Examples ofunsubstituted (C₁-C₂₀)alkyl are unsubstituted (C₁-C₂₀)alkyl;unsubstituted (C₁-C₁₀)alkyl; unsubstituted (C₁-C₅)alkyl; methyl; ethyl;1-propyl; 2-propyl; 1-butyl; 2-butyl; 2-methylpropyl; 1,1-dimethylethyl;1-pentyl; 1-hexyl; 1-heptyl; 1-nonyl; and 1-decyl. In one or moreembodiments, the R′ group is a substituted alkyl. Examples ofsubstituted (C₁-C₂₀)alkyl are substituted (C₁-C₂₀) alkyl, substituted(C₁-C₁₀)alkyl, and trifluoromethyl. In various embodiments, the R′ groupcomprises 2 to 12 carbon atoms, 2 to 6 carbon atoms, or 2 carbon atoms.In one or more embodiments, the R′ group may be C₂H₄, C₆H₁₂ or C₁₀H₂₀.

In one or more embodiments, the R″ group in the amino amide comprisingthe formula R—CO—NH—R′—NH—R″—NH₂ comprises an alkyl group. In one ormore embodiments, the R″ group is an unsubstituted alkyl. Examples ofunsubstituted (C₁-C₂₀)alkyl are unsubstituted (C₁-C₂₀)alkyl;unsubstituted (C₁-C₁₀)alkyl; unsubstituted (C₁-C₅)alkyl; methyl; ethyl;1-propyl; 2-propyl; 1-butyl; 2-butyl; 2-methylpropyl; 1,1-dimethylethyl;1-pentyl; 1-hexyl; 1-heptyl; 1-nonyl; and 1-decyl. In one or moreembodiments, the R″ group is a substituted alkyl. Examples ofsubstituted (C₁-C₂₀)alkyl are substituted (C₁-C₂₀) alkyl, substituted(C₁-C₁₀)alkyl, and trifluoromethyl. In various embodiments, the R′ groupcomprises 2 to 12 carbon atoms, 2 to 6 carbon atoms, or 2 carbon atoms.In one or more embodiments, the R′ group may be C₂H₄, C₆H₁₂ or C₁₀H₂₀.

In one or more embodiments, the emulsifier comprises an amino amidecomprising the formula R—CO—NH—R′—NH—R″—NH₂ where R is C₁₇H₃₅, R′ isC₂H₄, and R″ is C₂H₄.

In one or more embodiments, the emulsifier may have ahydrophilic-lipophilic balance (HLB) of 3 to 5. The HLB may be measuredaccording to a standard technique, such as Griffin's method which statesHLB=20×M_(h)/M where M_(h) is the molecular mass of the hydrophilicportion of the molecule and M is the molecular mass of the wholemolecule. The resulting HLB value gives a result on a scale of from 0 to20 in which a value of 0 corresponds to a completelyhydrophobic/lipophilic molecule and a value of 20 corresponds to acompletely hydrophilic/lipophobic molecule. Generally, a molecule havingan HLB of less than 10 is lipid-soluble (and thus water-insoluble) and amolecule having an HLB of greater than 10 is water-soluble (and thuslipid-insoluble).

In one or more embodiments, the oil phase includes a base oil. The oilphase of the oil-based drilling fluids may include a synthetic oil ornatural petroleum product as the base oil. The natural petroleum-derivedproduct may include oils such as a diesel oil or a mineral oil. Thesynthetic oil may comprise an ester or olefin. Further, the syntheticoil or natural petroleum product may be composed of hydrocarbons such asn-paraffins, iso-paraffins, cyclic alkanes, branched alkanes, ormixtures thereof. Example base oils include DF-1 and EDC 99-DW availablefrom Total S.A. (Paris, France) and Escaid™ 110 available fromExxonMobil Chemical Company (Spring, Tex., USA). In various embodiments,the oil-based drilling fluid composition may have from 10 wt. % to 40wt. %, from 10 wt. % to 25 wt. %, from 10 wt. % to 18 wt. %, from 12 wt.% to 30 wt. %, from 12 wt. % to 25 wt. %, from 12 wt. % to 20 wt. %,from 12 wt. % to 18 wt. %, from 15 wt. % to 20 wt. %, from 15 wt. % to19 wt. %, from 15 wt. % to 18 wt. %, or from 15 wt. % to 17 wt. % baseoil based on the total weight of the oil-based drilling fluidcomposition.

The aqueous phase of the oil-based drilling fluid may include water anda salt source. In one or more embodiments, the water includes one ormore of deionized, tap, distilled or fresh waters; natural, brackish andsaturated salt waters; natural, salt dome, hydrocarbon formationproduced or synthetic brines; filtered or untreated seawaters; mineralwaters; and other potable and non-potable waters containing one or moredissolved salts, minerals or organic materials. In some embodiments, theaqueous phase may comprise a salt brine made up of water and a saltchosen from one or more of calcium chloride, calcium bromide, sodiumchloride, sodium bromide, and combinations thereof, for example. Theoil-based drilling fluid may contain from about 2 wt. % to about 10 wt.% aqueous phase, based on the total weight of the oil-based drillingfluid. In various embodiments, the oil-based drilling fluid compositionmay have from 2 wt. % to 8 wt. %, from 2 wt. % to 6 wt. %, from 2 wt. %to 5 wt. %, from 3 wt. % to 10 wt. %, from 3 wt. % to 8 wt. %, from 3wt. % to 6 wt. %, from 4 wt. % to 10 wt. %, from 4 wt. % to 8 wt. %,from 4 wt. % to 6 wt. %, or from 4 wt. % to 5 wt. % aqueous phase, basedon the total weight of the oil-based drilling fluid composition. In someembodiments, the oil-based drilling fluid may have an oil-to-water ratioby volume of from 50:50 to 95:5, from 75:20 to 95:5, from 85:15 to 95:5,or from 90:10 to 95:5, for example. The oil-to-water ratio of theoil-based drilling fluid composition is the volumetric ratio calculatedas Oil:water=base oil+surfactant(s)+emulsifier(s)+wetting agent(s):water. The water component includes the aqueous part of all brines addedplus any water present in other additives.

The oil-based drilling fluid composition also includes one or moreadditives. Example additives include a wetting agent, a rheologymodifier, a fluid-loss control additive, and a weighting additive. Theoil-based drilling fluid composition may also optionally includealkalinity adjusters, electrolytes, glycols, glycerols, dispersion aids,corrosion inhibitors, defoamers, and other additives or combinations ofadditives.

In embodiments, the oil-based drilling fluid composition may include aweighting additive to increase the density of the oil-based drillingfluid. Weighting additives may be used to control formation pressuresand to help combat the effects of sloughing or heaving shales that maybe encountered in stressed areas. Any substance that is denser thanwater and that does not adversely affect other properties of thedrilling fluid can be used as a weighting material. In some embodiments,the weighting material may be a particulate solid having a specificgravity (SG) sufficient to increase the density of the drilling fluidcomposition by a certain amount without adding excessive weightingmaterial such that the drilling fluid composition cannot be circulatedthrough the wellbore. Examples of weight adjusting or density adjustingagents include barite (BaSO₄), galena (PbS), hematite (Fe₂O₃), magnetite(Fe₃O₄), manufactured iron oxide, ilmenite (FeO.TiO₂), siderite (FeCO₃),celesite (SrSO₄), dolomite (CaCO₃.MgCO₃), and calcite (CaCO₃).

The oil-based drilling fluid composition may include an amount ofweighting additive sufficient to increase the density of the drillingfluid composition to allow the drilling fluid composition to support thewellbore and prevent fluids in downhole formations from flowing into thewellbore. In embodiments, the oil-based drilling fluid composition mayinclude from 1 wt. % to 80 wt. % weighting additive based on the totalweight of the oil-based drilling fluid composition. In some embodiments,the oil-based drilling fluid composition may include from 1 wt. % to 75wt. %, from 20 wt. % to 80 wt. %, from 20 wt. % to 75 wt. %, from 50 wt.% to 80 wt. %, from 50 wt. % to 75 wt. %, from 60 wt. % to 80 wt. %,from 60 wt. % to 75 wt. %, from 65 wt. % to 80 wt. %, or from 70 wt. %to 80 wt. % weighting additive based on the total weight of theoil-based drilling fluid composition. In some embodiments, the oil-baseddrilling fluid composition may include from 64 wt. % to 85.3 wt. %weighting additive based on the total weight of the oil-based drillingfluid composition.

In embodiments, the oil-based drilling fluid composition may include arheology modifier, for example a viscosifier to impart non-Newtonianfluid rheology to the oil-based drilling fluid composition to facilitatelifting and conveying rock cuttings to the surface of the wellbore andto suspend the weighting material. Examples of viscosifiers may include,but are not limited to, organophilic clay, sepiolite, polyimide, dimericor trimeric fatty acids, or combinations of these viscosifiers. In someembodiments, the oil-based drilling fluid composition may optionallyinclude an organophilic hectorite clay, for example, VERSAGEL HTcommercially available from MI-SWACO, Houston, Tex. In some embodiments,the oil-based drilling fluid composition may optionally include anadditional or different organophilic clay, for example Bentone® 42commercially available from Elementis Specialties Inc, Highstown, N.J.An example oil-based drilling fluid composition may optionally includefrom 0.1 wt. % to 2 wt. % of a rheology modifier based on the totalweight of the oil-based drilling fluid composition. In some embodiments,the oil-based drilling fluid composition may optionally include from0.25 wt. % to 0.5 wt. % of each of VERSAGEL HT and Bentone 42 based onthe total weight of the oil-based drilling fluid composition. Theoil-based drilling fluid composition may optionally include othersuitable viscosifiers without deviating from the scope of the presentsubject matter.

The oil-based drilling fluid composition may optionally include at leastone alkalinity adjuster. In embodiments, the oil-based drilling fluidcomposition may optionally include at least one alkaline compound toadjust the alkalinity of the oil-based drilling fluid composition.Examples of alkaline compounds may include, but are not limited to, lime(calcium hydroxide or calcium oxide), soda ash (sodium carbonate),sodium hydroxide, potassium hydroxide, other strong bases, orcombinations of these alkaline compounds. It is noted that conjugatebases to acids with a pK_(a) of more than about 13 are considered strongbases. The alkaline compounds may react with gases, such as CO₂ or H₂Sfor example, encountered by the drilling fluid composition duringdrilling operations to prevent the gases from hydrolyzing components ofthe oil-based drilling fluid composition. Some example oil-baseddrilling fluid compositions may optionally include from 0.1 wt. % to 2wt. %, 0.4 wt. % to 1.8 wt. %, or 0.6 wt. % to 1.5 wt. % lime. Inembodiments, the oil-based drilling fluid composition may have analkalinity of 0 to 15 grams per liter (g/L) excess line.

In one or more embodiments, surfactants such as wetting agents may beadded to enhance the stability of suspensions or emulsions in theoil-based drilling fluid composition. Suitable wetting agents mayinclude fatty acids, organic phosphate esters, modified imidazolines,amidoamines, alkyl aromatic sulfates, and sulfonates. For example,SUREWET®, which is commercially available from M-I SWACO, Houston, Tex.,is an oil based wetting agent and secondary emulsifier that may be usedto wet fines and drill solids to prevent water-wetting of solids.Moreover, SUREWET® may improve thermal stability, rheological stability,filtration control, emulsion stability of wellbore fluids. VERSAWET®,which is commercially available from M-I LLC, Houston, Tex., is afurther wetting agent and is especially effective in difficult to wethematite systems. An example oil-based drilling fluid composition mayoptionally include from 0.1 wt. % to 2 wt. % of a wetting agent based onthe total weight of the oil-based drilling fluid composition. In someembodiments, the oil-based drilling fluid composition may optionallyinclude from 0.25 wt. % to 0.75 wt. % of each of SUREWET® based on thetotal weight of the oil-based drilling fluid composition. The oil-baseddrilling fluid composition may optionally include other suitable wettingagents without deviating from the scope of the present subject matter.

In one or more embodiments, fluid-loss control agents may be added tothe oil-based drilling fluid composition to reduce the amount offiltrate lost from the oil-based drilling fluid composition into asubsurface formation. Examples of fluid-loss control agents includeorganophilic (for example, amine-treated) lignite, bentonite,manufactured polymers, and thinners or deflocculants. When fluid-losscontrol agents are used, they may comprise from about 0.5 wt. % to about3.0 wt. % of the oil-based drilling fluid composition, based on thetotal weight of the drilling fluid. In various embodiments, fluid-losscontrol agents may comprise from about 0.5 wt. % to about 1.5 wt. %, 0.5wt. % to about 1.25 wt. %, 0.75 wt. % to about 2 wt. %, 0.75 wt. % toabout 1.5 wt. %, 0.75 wt. % to about 1.25 wt. %, 1 wt. % to about 2 wt.%, 1 wt. % to about 1.5 wt. %, or 1 wt. % to about 1.25 wt. % of theoil-based drilling fluid composition, based on the total weight of thedrilling fluid. Example fluid-loss control agents include VERSATROL™,VERSALIG™, ECOTROL™ RD, ONETROL™ HT, EMI 789, and NOVATECH™ F, allcommercially available from MI SWACO, Houston, Tex., and ADAPTA® whichis commercially available from Halliburton Energy Services, Inc. In someembodiments, the oil-based drilling fluid composition may optionallyinclude both ONETROL™ HT and ECOTROL™ RD in about a 10:1 weight ratiorespectively.

Optional suspending agents may be added to the oil-based drilling fluidcomposition to adjust the viscosity of the oil-based drilling fluidcomposition at a low shear rate sufficient to suspend all of thedrilling fluid components, by which the settling of components of theoil-based drilling fluid composition may be avoided. Examples ofsuspending agents include fatty acids and fibrous materials. Whensuspending agents are used, they may compose from about 0.0 wt. % toabout 1.0 wt. % or 0.01 to 0.5 wt. % of the oil-based drilling fluidcomposition, based on the total weight of the drilling fluid.

To maintain suspension of solids and cuttings in the oil-based drillingfluid composition during low speed drilling or between drillingoperations, viscosity greater than a threshold at lesser shear rates isadvantageous. In one or more embodiments, the oil-based drilling fluidhas a viscosity greater 400 cP at a shear rate of 10.22 seconds⁻¹ (s⁻¹)measured at 50° C. In various embodiments, the oil-based drilling fluidhas a viscosity greater than 410 cP, greater than 420 cP, greater than430 cP, or greater than 440 cP at a shear rate of 10.22 s⁻¹ measured at50° C. and atmospheric pressure. Conversely, it is advantageous to alsolimit the viscosity of the oil-based drilling fluid composition atlesser shear rates to avoid excess energy or force required to initiateor maintain drilling fluid circulation. In various embodiments, theoil-based drilling fluid has a viscosity less than 1500 cP, less than1000 cP, less than 800 cP, or less than 600 cP at a shear rate of 10.22s⁻¹ measured at 50° C.

Once drilling operations have commenced and the oil-based drilling fluidcomposition is circulating, the circulation of the oil-based drillingfluid composition assists in maintaining suspension of solids andcuttings in the oil-based drilling fluid composition. To avoid excessenergy requirements for oil-based drilling fluid composition circulationand to avoid applying excess pressure to the formations exposed in theborehole via the effect of the equivalent circulating density, it isadvantageous for the viscosity of the oil-based drilling fluidcomposition to be less than a threshold at greater shear rates. In oneor more embodiments, the oil-based drilling fluid has a viscosity lessthan 125 cP at a shear rate of 170 s⁻¹ measured at 50° C. andatmospheric pressure. In various embodiments, the oil-based drillingfluid has a viscosity less than 122 cP, less than 120 cP, less than 118cP, or less than 115 cP at a shear rate of 170 s⁻¹ measured at 50° C.

Having previously described the oil-based drilling fluid compositionsaccording to various embodiments, illustrative methods for preparing theoil-based drilling fluid compositions will now be described. The methodsfor preparing the oil-based drilling fluids may include mixing a baseoil, at least one emulsifier, and at least one wetting agent to form afirst mixture, in which the at least one emulsifier comprises an aminoamide comprising the formula R—CO—NH—R′—NH—R″—NH₂, where R is a fattyacid alkyl and R′ and R″ are alkyl groups. The ingredients of the firstmixture may be added to provide amounts previously described with regardto embodiments of the oil-based drilling fluid compositions. The methodsfor preparing the oil-based drilling fluid compositions may optionallyinclude mixing at least one rheology modifier and alkalinity adjusterinto the first mixture to form a second mixture. Again, the ingredientsof the second mixture may be added to provide amounts previouslydescribed with regard to embodiments of the oil-based drilling fluidcompositions. The methods for preparing the oil-based drilling fluidcompositions may optionally include mixing at least one fluid-losscontrol additive into the second mixture to form a third mixture. Again,the ingredients of the third mixture may be added to provide amountspreviously described with regard to embodiments of the oil-baseddrilling fluid compositions. The methods for preparing the oil-baseddrilling fluid compositions may further include mixing a brine solutioninto the first mixture or third mixture to form a fourth mixture. Theingredients of the fourth mixture may be added to provide amountspreviously described with regard to embodiments of the oil-baseddrilling fluid compositions. The methods for preparing the oil-baseddrilling fluid compositions may further include mixing a weightingadditive into the fourth mixture to form the oil-base drilling fluidcomposition. The ingredients of the oil-based drilling fluid compositionmay be added to provide amounts previously described with regard toembodiments of the oil-based drilling fluid compositions.

The oil-based drilling fluid compositions previously described, may bewell-suited for use in drilling operations on subterranean formations,particularly for drilling operations performed under HPHT conditions ofa wellbore pressure greater than 10,000 psi and a wellbore temperaturegreater than 300° F. (149° C.). Accordingly, embodiments of methods fordrilling in a subterranean well under high-pressure high-temperatureconditions may include providing an oil-based drilling fluid compositionaccording to any embodiment described in this specification. The methodfor drilling in a subterranean well under high-pressure high-temperatureconditions comprises operating a drill in a wellbore in the presence ofthe oil-based drilling fluid composition.

EXAMPLES

The following examples illustrate one or more additional features of thepresent disclosure. It should be understood that these examples are notintended to limit the scope of the disclosure or the appended claims inany manner.

Experimental Procedures

The general procedure for preparation of the amino amide emulsifiercomprising the formula R—CO—NH—R′—NH—R″—NH₂ (Formula 1 emulsifier) inaccordance with this disclosure includes adding 0.28 grams (g) of 1millimole (mmol) fatty acid (stearic acid), 3.09 milligrams (mg) of 0.05mmol boric acid, and 3 milliliters (ml) of toluene to a flask equippedwith Dean-Stark trap topped with a reflux condenser. Subsequently, 0.12g of 1.1 mmol amino amine (diethylenetriamine) was added to the reactionmixture under stirring. The reaction mixture was heated at refluxovernight (approximately 14 to 16 hours). The mixture was allowed tocool to room temperature and then was poured with stirring into hexaneleading to the immediate precipitation of a solid which was filtered offand washed with hexane to afford the desired amino amide emulsifiercomprising the formula R—CO—NH—R′—NH—R″—NH₂ in accordance withembodiments of this disclosure.

To compare the physical and rheological properties of a drilling fluidcontaining the Formula 1 emulsifier with those of a drilling fluidcontaining an industry standard emulsifier, two drilling fluids wereprepared. The two drilling fluids were based on the M-I SWACO RHADIANT™system that includes a blend of proprietary emulsifiers, wetting agents,and fluid-loss control agents specially tailored for oil-based fluidformulations. Specifically, a comparative drilling fluid, ComparativeExample 1, was prepared using SUREMUL®, as an emulsifier. A seconddrilling fluid, Example 2, was prepared by replacing SUREMUL® with theFormula 1 emulsifier. It is noted that the Formula 1 emulsifier wasreduced by 25% from the quantity of SUREMUL® in the replacement becauseSUREMUL® is 75% emulsifier dissolved in the base oil and the Formula 1emulsifier was pure emulsifier.

The Comparative Example 1 and Example 2 drilling fluids were formulatedusing the following ingredients: Saraline 185V, a synthetic oil drillingbase fluid, available from Shell; SUREMUL®, an amidoamine surfactant,available from M-I SWACO, LLC (Houston, Tex., USA); SUREWET®, a wettingagent, available from M-I SWACO, LLC (Houston, Tex., USA); MUL XT, anemulsifier for use in non-aqueous fluid systems, available from M-ISWACO, LLC (Houston, Tex., USA); VERSAGEL HT, a hectorite clayviscosifier for aiding in filtration control, available from M-I SWACO,LLC (Houston, Tex., USA); ONE-TROL™ HT, an amine-treated tanninfiltration control additive designed for use in oil and synthetic-basedrilling fluid systems, available from M-I SWACO, LLC (Houston, Tex.,USA); ECOTROL RD, a filtration control additive designed for use in oiland synthetic-base drilling fluid systems, available from M-I SWACO, LLC(Houston, Tex., USA); and barite (BaSO₄) weighting agent, available fromM-I SWACO, LLC (Houston, Tex., USA).

The Comparative Example 1 and Example 2 drilling fluids were prepared in30.88 g and 25.98 g quantities respectively using a magnetic stir bar.The formulations for the Comparative Example 1 and Example 2 drillingfluids are provided in Table 1. To prepare the drilling fluids, the baseoil, emulsifiers, and wetting agents were mixed together first for 10minutes during stage 1. Specifically, SUREMUL® was added to ComparativeExample 1 as an emulsifier and the Formula 1 emulsifier was added toExample 2 as an emulsifier. Then the viscosity modifiers and rheologymodifiers were added and mixed for another 20 minutes during stage 2.Next, in stage 3 the fluid-loss control additives were added and mixedfor 20 minutes, followed by brine and fresh water in stage 4 and baritein stage 5, which were mixed for 30 minutes and 40 minutes,respectively. The quantity of base oil used and barite as a wt. % wereslightly different for Comparative Example 1 and Example 2 to provide aspecific gravity of 2.20 and an oil/water ratio of 90.0, for bothComparative Example 1 and Example 2.

TABLE 1 Formulation and Mixing Procedure for HPHT Oil-Based DrillingFluids Comparative Example 1 Example 2 Mixing Order Ingredient Function(wt. %) (wt. %) and Time Saraline 185V Base Oil 15.805 16.094 Stage 1SUREMUL Emulsifier 1.296 0 (10 min) Formula 1 Emulsifier 0 0.972Emulsifier SUREWET Wetting 0.518 0.519 Agent MUL XT Emulsifier 0.5180.519 VERSAGEL HT Rheology 0.356 0.357 Stage 2 Modifier (20 min) Bentone42 Rheology 0.356 0.357 Modifier Lime Alkalinity 0.777 0.778 ModifierONE-TROL HT Fluid Loss 1.036 1.038 Stage 3 Control (20 min) AdditiveECOTROL RD Fluid Loss 0.104 0.104 Control Additive CaCl₂ brine Internal3.692 3.735 Stage 4 Phase (30 min) Fresh water Internal 0.764 0.778Phase Barite Weighting 74.777 74.750 Stage 5 Agent (40 min) Total 99.999100.001 120 min Specific Gravity 2.20 2.20 Oil/Water Ratio (volumetric)90.0 90.0

The Comparative Example 1 and Example 2 drilling fluids were leftstatically after mixing for 17 hours and then were inspected for saggingand fluid separation prior to rheology measurements. Fluid separationand sagging were inspected visually. Specifically, inspection of visualseparation of solids and liquid was undertaken. Sagging was alsoexamined by inserting a micro spatula into the mud to check if the mudwas of similar texture (subjectively hard or soft) throughout from topto bottom and if there was separation and settlement of solids such thatsolids were no longer homogenously distributed throughout the drillingfluid. If there was sagging, as evidenced by separation and settlementof the solids, then the mud would appear softer at the top and becomeharder at the bottom of the vessel in which the drilling fluid wasstatically left.

The viscosities of the drilling fluids were tested using a stress andstrain controlled rheometer (Discover Hybrid Rheometer from TAInstrument, New Castle, Del.). The geometry utilized in the rheometerwas 25 mm rough stainless steel parallel plates. This geometry wasselected due to the presence of barite in the sample. This geometry witha roughened surface was selected to minimize slip between the drillingfluid and plates due to the presence of barite in the sample. The gapbetween the stainless steel plates was set at 300 μm. Viscositymeasurements as a function of shear rate were carried out from 0.004 to2000 s⁻¹ at 0° C. and 50° C. at atmospheric pressure. When no force wasapplied, the Comparative Example 1 and Example 2 drilling fluids gelledand were strong enough to hold drill solids and weighting materials suchas barite. Shear rate experiments provide useful viscosity informationof the fluid and whether the fluid has zero shears or is shear thinning.The shear rate experiments also indicated shear rate at which thedrilling fluids deform.

Results from the viscosity testing, % Strain, Sagging, and the fluidseparation testing, are provided in Tables 2 and 3.

TABLE 2 HPHT Oil-Based Drilling Fluids: Viscosities at 50° C. Oil-BasedDrilling Fluid Viscosity at shear rate Viscosity at shear rate at 50° C.of 10.22 s⁻¹ of 170 s⁻¹ Comparative Example 1 358 128 Example 2 444 111

With reference to FIG. 1 and Table 2, both Comparative Example 1 andExample 2 exhibited shear-thinning behavior regardless of theirformulation and temperature at testing. However, at 50° C., Example 2had greater viscosity at low shear rates of 10.22 s⁻¹ than ComparativeExample 1 at the same temperature and shear rate, thus allowing theExample 2 drilling fluid to better hold solids while stationary than theComparative Example 1 drilling fluid. Conversely, at 50° C. Example 2had lesser viscosity at high shear rates of 170 s⁻¹ than ComparativeExample 1 at the same temperature and shear rate. The lesser viscosityof Example 2 translates to a requirement for less energy to circulatethe drilling fluid during drilling operations than that which would berequired for Comparative Example 1. The viscosity of the Example 2drilling fluid becomes less than the viscosity of the ComparativeExample 1 drilling fluid at approximately 95 to 100 s⁻¹ and Example 2and Comparative Example 1 have similar viscosities around the shearrates of 80 s⁻¹. The relative viscosities of Example 2 and ComparativeExample 1 at 50° C. indicates Example 2 would be better to hold solidswhile stationary as a result of the greater viscosities at low shearrates while simultaneously exhibiting a need for less power duringdrilling fluid circulation as a result of the lesser viscosity at highshear rates when compared with Comparative Example 1.

Example 2 drilling fluid showed gel characteristics, such that theywould gel as soon as stress is removed. This correlates to a drillingfluid which would gel as soon as drilling is halted such that thedrilling fluid would effectively support cuttings.

TABLE 3 Oil-Based Drilling Fluids: % Strain and Separation % Strain whendeformed Oil-Based Drilling Fluid at 50° C. Sagging Fluid SeparationComparative Example 1 0.399 No Trace Example 2 0.402 No Trace

Both Example 2 and Comparative Example 1 did not show sagging anddemonstrated only trace separation after standing static for 17 hoursafter preparation. Both Example 2 and Comparative Example 1 deformed atapproximately the same strain at 50° C., as shown in Table and FIGS.2-3, therefore both would require similar power to initiate circulation.Additionally, as shown in FIG. 2, Example 2 became more fluid (G″>G′) atlower strains than Comparative Example 1, thereby requiring less powerduring circulation. In FIG. 3, the phase angles of Example 2 andComparative Example 1 also confirmed that Example 2 becomes more fluidicat lower strains than Comparative Example 1 at 50° C.

In FIGS. 2 and 3, the storage modulus (G′), loss modulus (G″) and phaseangle measurements as a function of % strain were monitored at aconstant frequency of 1 radian per second (rad s¹) and temperatures of0° C. and 50° C. from % strain of 0.01 to 10000 to identify the linearviscoelastic region. The test involves applying small incrementaloscillating (clockwise then counter-clockwise in rotation) stresses tothe mud and monitoring its resulting strain (i.e. deformation) response.These measurements could also be used to identify the strength of thedispersion structure (settling stability) and resilience. G′, G″ andphase angle relate to the viscoelastic properties of the fluid. G′describes the elastic properties of the drilling fluid while G″describes the viscous properties of the drilling fluid. Therefore whenG′ is greater than G″ the drilling fluid behaves like a solid materialand when less than G″ then as liquid. Gelled fluids initially showlinear viscoelastic region at low strains, but G′ and G″ decrease as %strain increases, G′ eventually becoming less than G″ and resulting anan increase in phase angle. Phase angle is G″/G′ where the phase angleof a Newtonian fluid such as water is 90°. It is noted that the strongerthe gel, the greater the strain required to break the gel, hencerequiring more power to start the circulation.

Example 2 and Comparative Example 1 were tested for thermal stability.Thermal stability was tested using thermogravimetric analysis (TGA). TheTGA demonstrated Example 2 retained thermal stability until 170° C.while Comparative Example 1 demonstrated thermal stability until only100° C.

It should be understood that the various aspects of the oil-based fluidcomposition, method of making the same, and method for drilling asubterranean well utilizing the same are described and such aspects maybe utilized in conjunction with various other aspects.

In a first aspect, the disclosure provides an oil-based drilling fluidcomposition. The oil-based drilling fluid composition includes an oilphase having a base oil; an aqueous phase; at least one emulsifier; andone or more additives chosen from a wetting agent, a rheology modifier,a fluid-loss control additive, and a weighting additive. The at leastone emulsifier comprises an amino amide comprising the formulaR—CO—NH—R′—NH—R″—NH₂, where R is a fatty acid alkyl and R′ and R″ arealkyl groups.

In a second aspect, the disclosure provides the drilling fluid of thefirst aspect, in which the disclosure provides the drilling fluid of thefirst aspect, in which R is selected from C₁₅H₃₁, C₁₇H₃₅, C₂₁H₄₃ orC₈—H₁₇CHCHC₇H₁₄.

In a third aspect, the disclosure provides the drilling fluid of any ofthe first or second aspects, in which R′ is selected from C₂H₄, C₆H₁₂ orC₁₀H₂₀.

In a fourth aspect, the disclosure provides the drilling fluid of any ofthe first through third aspects, in which R″ is selected from C₂H₄,C₆H₁₂ or C₁₀H₂₀.

In a fifth aspect, the disclosure provides the drilling fluid of thefirst aspect, in which R is C₁₇H₃₅, R′ is C₂H₄, and R′ is C₂H₄.

In a sixth aspect, the disclosure provides the drilling fluid of any ofthe first through fifth aspects, in which the oil-based drilling fluidcomprises from 10% by weight to 20% by weight base oil, based on thetotal weight of the oil-based drilling fluids.

In a seventh aspect, the disclosure provides the drilling fluid of anyof the first through sixth aspects, in which the oil-based drillingfluid comprises from 0.05% by weight to 5.0% by weight emulsifier, basedon the total weight of the oil-based drilling fluids.

In an eighth aspect, the disclosure provides the drilling fluid of anyof the first through seventh aspects, in which the oil-based drillingfluid comprises from 0.1% by weight to 2.0% by weight wetting agent,based on the total weight of the oil-based drilling fluids.

In a ninth aspect, the disclosure provides the drilling fluid of any ofthe first through eighth aspects, in which the oil-based drilling fluidcomprises from 0.1% by weight to 2.0% by weight rheology modifier, basedon the total weight of the oil-based drilling fluids.

In a tenth aspect, the disclosure provides the drilling fluid of any ofthe first through ninth aspects, in which the oil-based drilling fluidcomprises from 0.5% by weight to 2.0% by weight fluid-loss controladditive, based on the total weight of the oil-based drilling fluids.

In an eleventh aspect, the disclosure provides the drilling fluid of anyof the first through tenth aspects, in which the oil-based drillingfluid comprises from 3.0% by weight to 5.0% by weight brine solution,based on the total weight of the oil-based drilling fluids.

In a twelfth aspect, the disclosure provides the drilling fluid of anyof the first through eleventh aspects, in which the oil-based drillingfluid comprises from 64% by weight to 85.3% by weight weightingadditive, based on the total weight of the oil-based drilling fluids.

In a thirteenth aspect, the disclosure provides the drilling fluid ofany of the first through twelfth aspects, in which the oil-baseddrilling fluid comprises from 0.1% by weight to 2.5% by weight of theemulsifier, based on the total weight of the oil-based drilling fluids.

In a fourteenth aspect, the disclosure provides the drilling fluid ofany of the first through thirteenth aspects, in which the rheologymodifier comprises one or more of an organophilic clay, a hectoriteclay, a dimeric fatty acid, a trimeric fatty acid, a polyamine, asepiolite, and an attapulgite.

In a fifteenth aspect, the disclosure provides the drilling fluid of anyof the first through fourteenth aspects, in which the weight additivecomprises one or more of barite, calcite, aragonite, iron carbonate,zinc carbonate, manganese tetroxide, zinc oxide, zirconium oxide,hematite, ilmenite, and lead carbonate.

In a sixteenth aspect, the disclosure provides the drilling fluid of anyof the first through fifteenth aspects, in which the viscosity at ashear rate of 10.22 s⁻¹ measured at 50° C. is greater than 400 cP.

In a seventeenth aspect, the disclosure provides the drilling fluid ofany of the first through sixteenth aspects, in which the viscosity at ashear rate of 170 s⁻¹ measured at 50° C. is less than 125 cP.

In an eighteenth aspect, the disclosure provides a method for making anoil-based drilling fluid composition. The method includes mixing a baseoil, at least one emulsifier, and optionally at least one wetting agentto form a first mixture in which the at least one emulsifier includes anamino amide having the formula R—CO—NH—R′—NH—R″—NH₂, where R is a fattyacid alkyl and R′ and R″ are alkyl groups. The method further includesoptionally, mixing at least one rheology modifier, and a alkalinityadjuster into the first mixture to form a second mixture; optionally,mixing at least one fluid-loss control additive into the second mixtureto form a third mixture; mixing a brine solution into the first mixtureor the third mixture to form a fourth mixture; and mixing a weightingadditive into the fourth mixture to form the oil-based drilling fluidcomposition:

In a nineteenth aspect, the disclosure provides the method of theeighteenth aspect, in which R is selected from C₁₅H₃₁, C₁₇H₃₅, C₂₁H₄₃ orC₈H₁₇CHCHC₇H₁₄.

In a twentieth aspect, the disclosure provides the method of any of theeighteenth or nineteenth aspects, in which R′ is selected from C₂H₄,C₆H₁₂ or C₁₀H₂₀.

In a twenty-first aspect, the disclosure provides the method of any ofthe eighteenth through twentieth aspects, in which R″ is selected fromC₂H₄, C₆H₁₂ or C₁₀H₂₀.

In a twenty-second aspect, the disclosure provides the method of any ofthe eighteenth through twenty-first aspects, in which R is C₁₇H₃₅, R′ isC₂H₄, and R′ is C₂H₄.

In a twenty-third aspect, the disclosure provides the method of any ofthe eighteenth through twenty-second aspects, in which the oil-baseddrilling fluid composition comprises from 10% by weight to 20% by weightbase oil, based on the total weight of the oil-based drilling fluidcomposition.

In a twenty-fourth aspect, the disclosure provides the method of any ofthe eighteenth through twenty-third aspects, in which the oil-baseddrilling fluid composition comprises from 0.05% by weight to 5.0% byweight emulsifier, based on the total weight of the oil-based drillingfluid composition.

In a twenty-fifth aspect, the disclosure provides the method of any ofthe eighteenth through twenty-fourth aspects, in which the oil-baseddrilling fluid composition comprises from 0.1% by weight to 2.0% byweight wetting agent, based on the total weight of the oil-baseddrilling fluid composition.

In a twenty-sixth aspect, the disclosure provides the method of any ofthe eighteenth through twenty-fifth aspects, in which the oil-baseddrilling fluid composition comprises from 0.1% by weight to 2.0% byweight rheology modifier, based on the total weight of the oil-baseddrilling fluid composition.

In a twenty-seventh aspect, the disclosure provides the method of any ofthe eighteenth through twenty-sixth aspects, in which the oil-baseddrilling fluid composition comprises from 0.5% by weight to 2.0% byweight fluid-loss control additive, based on the total weight of theoil-based drilling fluid composition.

In a twenty-eighth aspect, the disclosure provides the method of any ofthe eighteenth through twenty-seventh aspects, in which the oil-baseddrilling fluid composition comprises from 3.0% by weight to 5.0% byweight brine solution, based on the total weight of the oil-baseddrilling fluid composition.

In a twenty-ninth aspect, the disclosure provides the method of any ofthe eighteenth through twenty-eighth aspects, in which the oil-baseddrilling fluid composition comprises from 64% by weight to 85.3% byweight weighting additive, based on the total weight of the oil-baseddrilling fluid composition.

In a thirtieth aspect, the disclosure provides the method of any of theeighteenth through twenty-ninth aspects, in which the oil-based drillingfluid composition comprises from 0.1% by weight to 2.5% by weight of theemulsifier, based on the total weight of the oil-based drilling fluidcomposition.

In a thirty-first aspect, the disclosure provides the method of any ofthe eighteenth through thirtieth aspects, in which the rheology modifiercomprises one or more of an organophilic clay and a hectorite clay.

In a thirty-second aspect, the disclosure provides the method of any ofthe eighteenth through thirty-first aspects, in which the weightadditive comprises one or more of barite, hematite, ilmenite, calcite,aragonite, iron carbonate, zinc carbonate, manganese tetroxide, zincoxide, zirconium oxide, and lead carbonate.

In a thirty-third aspect, the disclosure provides the method of any ofthe eighteenth through thirty-second aspects, in which the viscosity ofthe oil-based drilling fluid composition at a shear rate of 10.22 s⁻¹measured at 50° C. is greater than 400 cP.

In a thirty-fourth aspect, the disclosure provides the method of any ofthe eighteenth through thirty-third aspects, in which the viscosity ofthe oil-based drilling fluid composition at a shear rate of 170 s⁻¹measured at 50° C. is less than 125 cP.

In a thirty-fifth aspect, the disclosure provides a method for drillinga subterranean well. The method includes providing an oil-based drillingfluid composition according to any one of the first through seventeenthaspects; and introducing the oil-based drilling fluid composition into awellbore.

In a thirty-sixth aspect, the disclosure provides the method of thethirty-fifth aspect, in which the method further includes operating adrill in the wellbore.

In a thirty-seventh aspect, the disclosure provides the method of any ofthe thirty-fifth or thirty-sixth aspects, in which the wellbore has awellbore temperature greater than 300° F. (148.9° C.).

In a thirty-eighth aspect, the disclosure provides the method of any ofthe thirty-fifth through thirty-seventh aspects, in which the wellborehas a wellbore pressure greater than 10,000 psi (68,948 kPa).

It should be understood that any two quantitative values assigned to aproperty may constitute a range of that property, and all combinationsof ranges formed from all stated quantitative values of a given propertyare contemplated in this disclosure. It should be appreciated thatcompositional ranges of a chemical constituent in a composition orformulation should be appreciated as containing, in some embodiments, amixture of isomers of that constituent. It should be appreciated thatthe examples supply compositional ranges for various compositions, andthat the total amount of isomers of a particular chemical compositioncan constitute a range.

Having described the subject matter of the present disclosure in detailand by reference to specific embodiments, it is noted that the variousdetails described in this disclosure should not be taken to imply thatthese details relate to elements that are essential components of thevarious embodiments described in this disclosure, even in cases where aparticular element is illustrated in each of the drawings that accompanythe present description. Rather, the claims included in this applicationshould be taken as the sole representation of the breadth of the presentdisclosure and the corresponding scope of the various embodimentsdescribed in this disclosure. Further, it should be apparent to thoseskilled in the art that various modifications and variations can be madeto the described embodiments without departing from the spirit and scopeof the claimed subject matter. Thus it is intended that thespecification cover the modifications and variations of the variousdescribed embodiments provided such modifications and variations comewithin the scope of the appended claims and their equivalents.

The invention claimed is:
 1. A method for drilling a subterranean well,the method comprising: providing an oil-based drilling fluidcomposition; and introducing the oil-based drilling fluid compositioninto a wellbore; wherein the oil-based drilling fluid compositioncomprises: an oil phase comprising a base oil; an aqueous phasecomprising water; at least one emulsifier, in which the at least oneemulsifier comprises an amino amide comprising the formulaR—CO—NH—R′—NH—R″—NH₂, where R is a fatty acid alkyl and R′ and R″ arealkyl groups; and one or more additives chosen from a wetting agent, arheology modifier a fluid-loss control additive, and a weightingadditive.
 2. The method of claim 1, where the method further comprisesoperating a drill in the wellbore.
 3. The method of claim 1, where thewellbore comprises a wellbore temperature greater than 300° F.
 4. Themethod of claim 1, where the wellbore comprises a wellbore pressuregreater than 10,000 psi.
 5. The method of claim 1, where R is selectedfrom C₁₅H₃₁, C₁₇H₃₅, C₂₁H₄₃ or C₈H₁₇CHCHC₇H₁₄.
 6. The method of claim 1,where R′ is selected from C₂H₄, C₆H₁₂ or C₁₀H₂₀.
 7. The method of claim1, where R″ is selected from C₂H₄, C₆H₁₂ or C₁₀H₂₀.
 8. The method ofclaim 1, where R is C₁₇H₃₅, R′ is C₂H₄, and R′ is C₂H₄.
 9. The method ofclaim 1, where the oil-based drilling fluid comprises from 0.05% byweight to 5.0% by weight emulsifier, based on the total weight of theoil-based drilling fluids.
 10. The method of claim 1, where theoil-based drilling fluid comprises from 0.1% by weight to 2.0% by weightrheology modifier, based on the total weight of the oil-based drillingfluids.
 11. The method of claim 10, where the rheology modifiercomprises one or more of an organophilic clay, a hectorite clay, adimeric fatty acid, a trimeric fatty acid, a polyamine, a sepiolite, andan attapulgite.
 12. The method of claim 1, where the oil-based drillingfluid comprises from 64% by weight to 85.3% by weight weightingadditive, based on the total weight of the oil-based drilling fluids.13. The method of claim 12, where the weight additive comprises one ormore of barite, calcite, aragonite, iron carbonate, zinc carbonate,manganese tetroxide, zinc oxide, zirconium oxide, hematite, ilmenite,and lead carbonate.
 14. The method of claim 1, where the viscosity at ashear rate of 10.22 s⁻¹ measured at 50° C. is greater than 400 cP. 15.The method of claim 1, where the viscosity at a shear rate of 170 s⁻¹measured at 50° C. is less than 125 cP.